Results: Searching for 'Hydrogen end uses'

The ETI has completed an assessment of the potential of using salt caverns, traditionally used to store natural gas, to store hydrogen (H₂) for power generation when the demand for electricity peaks daily. The use of these caverns would reduce the investment in clean power station capacity that the nation requires to build, and lift the average efficiency of the country’s responsive power system.

• The ETI has completed an assessment of the potential of using salt caverns, traditionally used to store natural gas, to store hydrogen (H₂) for power generation when the demand for electricity peaks daily. The use of these caverns would reduce the investment in clean power station capacity that the nation requires to build, and lift the average efficiency of the country’s responsive power system.
• Using salt caverns to store hydrogen has the potential to deliver clean, grid-scale load-following energy supplies
• The potential to store hydrogen changes inflexible gasification and reforming technology into competitive, highly flexible options for load following fossil fuel, biomass and waste fed power stations
• The UK has sufficient salt bed resource to provide tens of ‘GWe’ to the grid on a load following basis from H2 turbines
• Technologies making hydrogen from methane, such as steam methane reforming (SMR) and autothermal reforming (ATR) need to improve if they are to be competitve in power production from 100% hydrogen storage configurations – much of this improvement is already in hand in national clean fossil fuel, Carbon Capture and Storage and turbine  technology development programs
• Pre-combustion technology with storage offers flexibility to produce hydrogen and reduce the overall power generation investments

Today hydrogen has very limited use as an energy carrier in the UK. The hydrogen supply chain that does exist is almost exclusively for the chemical industry, with the hydrogen predominantly transported by vehicle in liquid or compressed form. The pipelines that do exist are used to move hydrogen relatively short distances and at relatively low volumes within the confines of chemical plants. Hydrogen is stored in reasonably large quantities in salt caverns, helping to balance somewhat intermittent consumption with the much steadier output from production plants. At present, hydrogen is predominantly produced from natural gas using a process known as steam methane reforming (SMR) but can be produced in a number of ways and from a variety of sources.

the ability to supply hydrogen from low carbon sources and the infrastructure to move it to demand locations are crucial to delivering hydrogen to any sector. Building an infrastructure to move hydrogen for use as an energy carrier would be starting from virtually nothing. Major investment will be needed to make this a reality, both in equipment and in the growth of a supply chain to deliver it. this will take time to establish. commitments around future demand for hydrogen, and the ability to produce it from low carbon sources, inevitably dictate an incremental approach which limits major infrastructure investment until demand and low carbon supply are further established.

No abstract available

ETI’s Strategy Analyst Alex Buckman presents “Evolution of our Energy System” at IET’s Power Academy 2017. Glasgow. This presentation covers:

• What is the ETI?
• Our energy system evolves around our choices
• Change happens fast
• Why do we need to balance?
• The tools at our disposal
• How much storage is needed?
• Vector Flexibility
• Demand Flexibility

In conclusion, we need to

• Create new energy systems, adapt existing ones and integrate them together
• Users define the energy system’s evolution, not the other way around
• Understand the implications of different scenarios so that we are prepared to evolve

The purpose and focus of the Hydrogen Turbines project is to improve the ETI’s understanding of the economics of flexible power generation systems comprising hydrogen production (with CCS), intermediate hydrogen storage (e.g. in salt caverns) and flexible turbines, and to provide data on the potential economics and technical requirements of such technology to refine overall energy system modelling inputs. The final deliverable (D2) comprises eight separate components. This document is D2 WP1 Report – providing results of a techno-economic assessment of options for hydrogen power production from coal, coal/biomass and gas.  It covers:

• Options for hydrogen production
• Techno-economic definition of the selected hydrogen production options
• Characterisation of basic design requirements for a cost effective hydrogen store
• Requirements / options for hydrogen turbines
• Economics of hydrogen pipelines
• Effects of hydrogen purity

The purpose and focus of the Hydrogen Turbines project is to improve the ETI’s understanding of the economics of flexible power generation systems comprising hydrogen production (with CCS), intermediate hydrogen storage (e.g. in salt caverns) and flexible turbines, and to provide data on the potential economics and technical requirements of such technology to refine overall energy system modelling inputs. The final deliverable (D2) comprises eight separate components. This document is D2 WP3 Report – providing a series of supporting studies:

• Identification of potential salt cavern locationswithin UK and first 25 miles of UK Continental Shelf;
• Salt cavern cost structure;
• HSE challenges of cavern construction and operation;
• Managing loss of containment;
• Licensing and build timeline;
• Alternative cavern use; and
• Landscapingstudy of alternatives to salt caverns.

The purpose and focus of the Hydrogen Turbines project is to improve the ETI’s understanding of the economics of flexible power generation systems comprising hydrogen production (with CCS), intermediate hydrogen storage (e.g. in salt caverns) and flexible turbines, and to provide data on the potential economics and technical requirements of such technology to refine overall energy system modelling inputs. The final deliverable (D2) comprises eight separate components. This document is D2 – Summary Report, providing an Overview of the project.

The ETI’s energy system modelling shows that flexible power generation systems comprising hydrogen generation with CCS, intermediate storage (particularly using salt caverns) and flexible turbines are attractive options for the UK. In the model described here, hydrogen is supplied from coal and biomass fired gasifiers and steam methane reformers, with CO₂ captured for storage. This permits the use at high load of capital intensive and relatively inflexible conversion and CCS equipment, filling hydrogen storage when power is not needed, and releasing hydrogen at short notice through turbines when power is at a premium

A review has been undertaken of selected CO₂ capture processes that are of interest to the ETI. The review provides descriptions of the technologies and outline discussion of the energy consumption, costs, percentage capture and development status, based on information in the public domain. The processes selected by the ETI were:

1. Post combustion capture membranes
2. Molten carbonate fuel cells for post combustion capture
3. Cryogenic separation (refrigerated and supersonic inertial separation)
4. Bi-phasic solvent scrubbing (liquid-liquid and liquid-solid)
5. Potassium carbonate scrubbing (pressurised and precipitating)

The performance, costs and status of the capture processes in coal fired power plants are summarised

The Energy Technologies Institute (ETI) is focused on accelerating the deployment of affordable, secure low-carbon energy systems for 2020 to 2050. One of the key technologies is carbon capture and storage (CCS). CCS could be particularly suitable for decarbonisation of intermediate load power generation, to complement other lower carbon generation technologies. There is currently a large requirement for intermediate load generation in the UK due to the variability of power demand and this requirement is expected to increase in future as greater amounts of variable renewable generation are used.Technologies which may be well suited in this regard are post combustion capture and production, storage, and use of hydrogen in gas turbine power plants. The ETI has requested supporting information on aspects of both of these technology options.


LMS100 gas turbine
The steam cycle of an LMS100 gas turbine could provide more than sufficient steam for an amine CO₂ capture unit. The energy efficiency penalty for CO₂ capture and compression at an LMS100 combined cycle plant would be about 9 percentage points, the same as at a combined cycle plant based on Frame 9F gas turbines. Simple cycle LMS100 plants are aimed at low-intermediate load power generation. An option for capturing CO₂ at such plants would be to install a simple HRSG that generates only low pressure steam for a CO₂ capture unit. Whether or not capturing CO₂ at such plants would be a feasible option would depend on the dynamic performance capabilities of the capture and compression units and the economics of CO₂ capture. There is limited scope to use heat from the LMS100’s compressor intercooler for a steamcycle or to generate low pressure steam for an amine CO₂ capture unit, due to the low temperature. Recuperation is unlikely to be an attractive modification to the LMS100 turbine, due to the low temperature difference between the turbine and compressor exit temperatures.

Hydrogen and co-fired gas turbines
A wide range of gas turbines are reported to be suitable for high-H₂ fuel gas, with addition of diluents (nitrogen or steam) for control of emissions. Up to 95% H₂ gas has been used in commercial turbines. The effects of using hydrogen and a diluent on the power output and efficiency of gas turbines depend on how the turbine is designed and operated and the system boundary, i.e. whether compression of nitrogen diluent is included. If nitrogen compression is outside of the system boundary, use of H₂ can resultin a significant increase in the thermal efficiency of a combined cycle plant but if it is within the system boundary there would typically be a small decrease. Published costs of gas turbines and combined cycle plants differ significantly between different sites and studies. Costs in UK£ are particularly uncertain due to variations in currency exchange rates. Typical costs of combined cycle and simple cycle plants based on large H or F class frame gas turbines appear to be around £500/kW and £330/kW respectively. Costs of plants based on smaller frame gas turbines or aero-derivatives appear to be about 50% greater, although this cost difference may be lower if plants based on large numbers of these smaller gas turbines were built.

Various scenarios for the UK’s power fleet composition in 2030 and 2040 were developed. Dispatch modelling in Plexos was carried out by Baringa on these fleets to investigate the role gas fed plants might have in future. This includes the ability to study load factors, stop/starts etc, and together with concomitant pricing, provide a picture of investment remuneration. The effect of key drivers is studied e.g. gas price.

THis slideset summarises:-

• Comparison of assumptions with Baringa Reference Case
• Market modelling results for Scenario 3 and Baringa Reference Case
• Asset modelling results for Scenario 3 and Baringa Reference Case
• Key conclusions and next steps

Various scenarios for the UK’s power fleet composition in 2030 and 2040 were developed. Dispatch modelling in Plexos was carried out by Baringa on these fleets to investigate the role gas-fed plants might have in future. This includes the ability to study load factors, stop/starts etc., and together with concomitant pricing, provide a picture of investment remuneration. The effect of key drivers is studied e.g. gas price

This slide set summarises the results for scenarios 1 and 2, along with the assumptions underlying the modelling, and these will be used to inform the final S3 market runs which will then be the basis of the subsequent asset valuation analysis

Key conclusions are

• Plant operation
  • H₂ turbine is highly sensitive to gas and carbon prices (more so to gas price)
  • CCGT CCS generation is far less sensitive and provides baseload power most of the time across the scenarios tested
  • Note the £35.1/tCO₂ and 7.7 £/GJ case has an output subsidy on CCS hence load factor is slightly higher
• Power prices
  • ESME fleet capacity margin is tight
  • CM clearing price cap hit and significant scarcity/uplift in wholesale prices
  • Subsidies for low carbon generation not having material impact on power prices (limited impact on CCGT CCS LF)
• Choice of final wholesale market scenario and ESME fleet is important as this will form the basis for asset valuation
• Drives asset dispatch against market prices
• Impacts CM clearing price (combination of de-rated capacity and revenues from wholesale market impacting bids)
• Potential changes to ESME run for scenario 3, before re-running PLEXOS
• Suggest usingBaringa commodity prices in ESME (based on recent IEA WEO publication) as more recent than ESME
• Continue to use ESME output carbon price, but noting that real 2030 policy incentive could be significantly lower
• Initial CM analysis based on ESME fleet suggests capacity is ‘too tight’ pushing up CM clearing and wholesale prices, need to revisit peak margin constraint in ESME to ensure more capacity is built –two parts to this:
• De-rating factors in ESME more optimistic compared to GB CM factors (except for interconnectors), but haven’t been updated for a while, question about whether to use BEIS CM numbers
• Reserve margin constraint currently 15% above peak demand, but this needs to covers a range of factors which may not all be included or have different underlying assumptions
• Current constraint only against end-use demand -needs to include distribution/transmission losses ~6.5%-
• Account for mark-up between ESME timeslice blocks to ½ hour peak (~7% delta in current scenarios)
• Actual reserve margin target (3.4% current CM target, although this may change in future)
• Largest infeed loss (currently ~900MW but expected to increase to e.g. 1600 with new nuclear)
• Timescales
• Need to have fully finalised scenario 3 wholesale market run (potentially different spot years of same mix) by early in w/c 20th to ensure sufficient time for asset analysis, but ideally bring this forward

Various scenarios for the UK’s power fleet composition in 2030 and 2040 were developed. Dispatch modelling in Plexos was carried out by Baringa on these fleets to investigate the role gas fed plants might have in future. This includes the ability to study load factors, stop/starts etc, and together with concomitant pricing, provide a picture of investment remuneration. The effect of key drivers is studied e.g. gas price

A new Central Decarb has been established for this analysis, which aims to provide a scenario that is somewhere between the previous HiBaseDecarb and HiRenDecarb scenarios in terms of capacity mix (provided by ETI) and emissions intensity and which also

• models 2025, 2030, 2035 and 2040 spot years;
• constrains the operation of H₂ turbines to a maximum of 40% as opposed to the baseload operation see in previous scenarios

Anumber of sensitivities have also been run including:

• HiBaseDecarb in 2040 with relaxed carbon intensity (by removing proxy CfDs and CO₂ price) to see the resulting emission intensity
• On Central Decarb in 2030 and 2040 to explore ‘small’ changes to Gas CCS capacity to see the impact on wholesale prices and emission intensity of power generation
• Increasing (and removing) CCS capacity and removing (adding) the same amount of CCGT in 2030 and 2040 to keep capacity margin at similar levels to Central Decarb (+/- 1 GW in 2030 and +/- 3 GW in 2040)

The modelling results for Central Decarb and sensitivities indicate the sensitivity of wholesale prices and emission intensity of power generation to CfD eligible low carbon baseload plant on the system

• Central Decarb results in an annual baseload price level between HiBaseDecarb and HiRenDecarb in 2030 but a very similar price level to HiRenDecarb (higher than HighBaseDecarb) in 2040 given the ongoing role of unabated gas plant at the margin
• Although outturn hourly prices can be volatile in the presence of significant intermittent renewables they appear particularly sensitive to the level to the level of subsidized low carbon baseload plant in the 2040s, as this leads to collapse in prices for a significant portion of the year when demand is low, as seen in the Central Decarb sensitivities and the original HighBaseDecarb run
• Removing the distortions to dispatch and prices caused by CfDs on baseload plant is unlikely to change the economics for a mid-merit H₂ turbine plant as this does not materially change the highest 1/3 of prices seen across the year (as shown in the HighBaseDecarb sensitivity)

With the growth of renewables a clean, dispatchable power source will be required in the 2030s. One scheme for providing this involves storing large quantities of H₂ in salt caverns, and to use the inventory to produce power or heat during peak hours. Although H₂ is stored already in caverns in the UK, there has been little work on the effect of rapid repetitive cycling on cavern integrity. The suitability of UK salt caverns for use in storing H₂ in rapid cycle mode is examined, based on detailed geotechnical analysis of saltfields in Yorkshire, Teesside and Cheshire. A detailed analysis is carried out by Atkins on a Cheshire cavern, using a combination of superimposed seasonal and daily demand patterns .The limitations of today’s market offering for firing H₂ in gas turbinesis described. Outline costing for schemes taking H₂from salt caverns and producing power are presented in the main report.

These are the appendices to the main report:

• A: Baseline Information and Assumptions
• B: Power Generation
• C: Surface Plant Process Design
• D: Cavern Storage
• E: Economic Viability
• F: Low Carbon Case
• G: Cheshire Case Study: Cavern Cyclic Loading Impact

With the growth of renewables, a clean, dispatchable power source will be required in the 2030s. One scheme for providing this involves storing large quantities of H₂ in salt caverns, and to use the inventory to produce power or heat during peak hours. Although H₂ is stored already in caverns in the UK, there has been little work on the effect of rapid repetitive cycling on cavern integrity. The suitability of UK salt caverns for use in storing H₂ in rapid cycle mode is examined, based on detailed geotechnical analysis of saltfields in Yorkshire, Teesside and Cheshire. A detailed analysis is carried out by Atkins on a Cheshire cavern, using a combination of superimposed seasonal and daily demand patterns .The limitations of today’s market offering for firing H₂ in gas turbines is described. Outline costing for schemes taking H₂ from salt caverns and producing power are presented

Optimal annual decarbonisation pathways to 2050 considering capacity and operational dispatch requirements, and current policy momentum effects

• ETI commissioned Baringa to undertake detailed analysis of what the cost optimal power sector capacity mix could look like around the 2030 point on the pathway to 2050, which allows for feasible operation (in line with GB’s reliability standard for a loss of load expectation of 3 hours per year) and which is consistent with a trajectory that enables the UK to meet its longer term, economy-wide emissions target.
• The analysis was undertaken in PLEXOS using the LT Plan (Long-Term) functionality that is available. A model was developed that minimises the total costs (capital, fixed operating and variable operating costs) of generation while ensuring the security of supply and meeting the carbon targets. For existing capacity wehave used our detailed in-house generation database that includes all power plants that participate in the wholesale markets along with their operational characteristics. The plant retirement decisions are an exogenous input to the model.
• The costs of new entry capacity were mainly advised from the ESME database while the operating characteristics were a combination of ETI data supplemented by additional Baringa information where relevant (e.g. ramp rates or start costs for more detailed operational analysis which are not present in the ESME database). Fossil fuel prices were based on near term forward prices and International Energy Agency’s (IEA) long-term projections as the most recent available set of assumptions. A carbon intensity target was set at 90gCO₂/kWh for 2030 and to net zero carbon emissionsfor 2050 (linear interpolation in between)
• We simulated the GB power market for the horizon of 2022 to 2050 using the inputs described above. The simulation was run on annual basis with a reduced chronology (6 sample days per year with hourly dispatch and representation of interconnected market prices from Baringa’s pan-European power model). In the period 2022-2030, all coal and some older gas plants are decommissioned. The carbon intensity target remains high during that period and many technologies such as CCS and Nuclear remain expensive. As a result most of new capacity deployment comes from CCGT.
• Most of the peaking capacity requirements for that period are met by OCGTs. In the period 2030-2050, carbon intensity target drops significantly and therefore there is need for more low carbon capacity. In this period, Nuclear is the dominant baseload capacity build and required new peaking additions are met by compressedair electricity storage and pumped heat electricity storage, on top of the existing pumped hydro capacity (from a set of battery and flow battery options).

Detailed analysis of cost-optimal annual decarbonisation pathways to 2050 considering capacity and operational dispatch requirements, and current policy momentum effects

• Using the optimised pathway capacity mix, we also simulated the 2030 spot year in a detailed way (full hourly dispatch), generating projections of dispatch and prices for that year. Whilst the pathway analysis applied direct CO₂ intensity constraint as part of the optimisation, using outputs from this analysis it is possible to infer what level the carbon price would have to reach to meet the 2030 intensity target. This requires ~58GBP per ton of CO₂ to achieve the equivalent 90gCO₂/kWh target given the Base Case capacity mix in 2030. In terms of the broader system operation in 2030 most of the flexibility is provided by CCGTs while OCGT only generates at periods of very high net load (demand net of wind and solar generation). Gas CCS and Nuclear are used for baseload generation.
• In addition, we ran several sensitivities and compared these to the base case (alongside a range of other National Grid, CCC, ETI and Baringa scenarios):?
  • In Low Demand, significantly less baseload capacity is built over the entire horizon especially nuclear and CCS
  • In Low Fuel Prices, Gas CCS is favoured as the main baseload unit at the expense of nuclear
  • In Low Interconnection, there is need for more capacity - especially baseload because GB is expected to be a net importer in the medium term
  • In High Renewables, the need for baseload capacity decreases but additional OCGTs and storageunits are required to provide peak / flexible capability
  • In Flexible EVs, the flexibility of the electric vehicles reduces the requirement for dedicated storage units
  • In Constrained CCS, the restrictions of CCS in the 20s/early 30s, causes a permanent change to the system favouring renewables and storage
  • In Constrained Nuclear, the restrictions of nuclear in the 20s favour the deployment of CCS technologies and renewables

Various scenarios for the UK’s power fleet composition in 2030 and 2040 were developed. Dispatch modelling in Plexos was carried out by Baringa on these fleets to investigate the role gas-fed plants might have in future. This includes the ability to study load factors, stop/starts etc., and together with concomitant pricing, provide a picture of investment remuneration. The effect of key drivers is studied e.g. gas price

This slideset summarises the modelling results of various scenarios for the UK’s power fleet composition in 2030 and 2040. Dispatch modelling in Plexos was carried out by Baringa on these fleets to investigate the role gas-fed plants might have in future. The information shown covers

• Baringa Reference Case assumptions
• Role of gas in the GB power sector
• Missing money for Gas CCS plant
• Capacity Assumptions underlying the work

The ETI’s energy system modelling shows that flexible power generation systems comprising hydrogen generation with CCS, intermediate storage (particularly using salt caverns) and flexible turbines are attractive options for the UK. In the model described here, hydrogen is supplied from coal and biomass fired gasifiers and steam methane reformers, with CO₂ captured for storage. This permits the use at high load of capital intensive and relatively inflexible conversion and CCS equipment, filling hydrogen storage when power is not needed, and releasing hydrogen at short notice through turbines when power is at a premium.

This executive summary covers the objectives and main findings of the five work packages, and suggests the next steps.

Infographic showing how hydrogen could help in the 10 year transition to low carbon.

No abstract available

No abstract available

ETI’s Strategy Director Jo Coleman presented “Network Transition Challenges” at the Energy Institute’s energy storage 2016 - prospects for scaling up UK storage capacity conference.

• Energy networks are a core part of the energy system
• Overarching challenges for transitioning networks
• Integrating networks to optimiseacross energy vectors and deliver flexibility
• Decarbonising heat through single and multi-vector routes
• To what extent is energy storage needed?
• Using H₂ storage to maximise use of CCS investment in the power system
• How might storage be operated?
• Salt caverns for hydrogen storage in conjunction with flexible turbines
• Pumped Heat Electrical Storage